Nozzles are used in a variety of applications and for several applications the performance of the nozzle is related to the amount of fluid entrained into the fluid path being ejected from the nozzle. Typically, nozzle designs incorporating entrainment properties are utilized in any fluid medium where fluid turbulence exists around the nozzles exterior surface and entrainment of the fluid surrounding the nozzle into the ejected fluid path is desired.
For purposes of clarity, fluid, as used herein, is intended to encompass any medium which may be emitted through a nozzle opening including, but not limited to gases, foams, mists and the like.
Nozzles requiring entrainment properties are often used in subterranean drilling applications for hydrocarbons due to the necessity to remove cuttings from the drilling fluid that inhibit the drill bit's rate of penetration. Nozzles are typically incorporated into a variety of different drill bits. For example, rotary drill bits are used in the drilling of deep holes, such as oil wells. Some are polycrystalline diamond compact ("PDC") bits with segmented rows or sectors of diamond hardened cutters; others are rotary cone drill bits, rock bits and/or fixed cutter bits. In each bit, however, the bit body upper end is threaded for attachment to the lower end of the drill line made of pipe. In normal drilling operations, the drill line pipe is rotated thus, forcing the rock bit into the earth. The sectors of teeth in a PDC bit or the cones in a rotary cone bit travel about the centerline of the drill bit and the rock cutters dig into the geological formation to fail scrape, crush and/or fracture it. The bit body also serves the function of a terminal pipe fitting to control and route drilling fluid from inside the drill line pipe out through a plurality of mud nozzles housed in the drill bit and up the annulus between the drill column and the wellbore.
Vertical channels, sometimes called junk slots, are formed between the exterior wall of the PDC bit body adjacent the nozzle locations and the borehole wall to facilitate the flow of fluid and entrained cuttings from the drilling zone. Inadequate removal of cuttings from between the cutter teeth in the drill bit and the formation rock causes more substantial rock chips on the hole bottom to be ground to a paste by the bit. For example, a cube of particle 200 microns on each side, if allowed to remain in the borehole, could be ground into 8 million 1 micron cubes. These cuttings, called "drilled solids" approach colloidal size and hydrate in the fluid, increasing fluid viscosity at the bit, also referred to as "plastic viscosity." As the plastic viscosity of the mud increases, the drilling rate decreases because the mud must get under a chip quickly so the bit cutters do not grind the chip instead of formation rock. If viscosity is high, the fluid cannot get under the chip rapidly and efficiently flush cuttings from the hole bottom. This impedes the penetration of the rock bit into the geological formation, abrasively wears the cutters, causes excessive drag and can produce well bore damage. Moreover, if the drilled solids are left in the mud, and viscosity of the mud in the annulus increases, resulting in thick filter cakes that reduce the area for moving mud up the annulus. This may lead to lost circulation, formation damage and stuck drill pipe.
The prior art has recognized that the pressure differential between the drilling fluid and the formation fluid effects the removal of cuttings from the borehole bottom and reduces the rate of penetration. Various techniques have been employed to counteract the foregoing effects in order to cause the fluid emerging from the bit nozzles to clean the bottom of the hole. One technique forces the fluid into the hole bottom as hard as possible, commonly referred to as "optimizing hydraulic impact." Another technique causes the fluid to expend as much power across the nozzle as possible, referred to as "optimizing hydraulic horsepower."
The conventional mud nozzle in a drilling bit is usually an axially symmetrical circular orifice. Generally, the stream expands out substantially conically after leaving the nozzle. In a PDC bit, the jets are typically spaced in front of the leading edge of a row or sector of teeth. In a rotary cone bit, a nozzle is provided for each rotary rock cutter and is positioned in the bit to direct a high velocity of fluid downward between the cutters and against the well bore wall. The positioning of the nozzle will thus, wash the face of the cutter cones and flush cuttings through to the annulus.
High pressure nozzles for injecting drilling fluid into the borehole have not satisfactorily provided the desired efficient removal of rock chips through to the annulus. It is also well known that turbulent pressure fluctuations have been found to provide lifting forces sufficient to overcome rock chip hold down to remove rock debris from the hole bottom. This technique uses the rock bit itself and facilitates drilling of the wellbore. Substantial effort has been directed to the foregoing problems of cutting removal and bit balling.
For example, Hayatdavoudi in U.S. Pat. Nos. 4,436,166 and 4,512,420, includes a nozzle and a drilling sub above the drilling bit. The nozzle is oriented to eject drilling fluid from the sub into the annulus above the bit with a horizontal velocity component tangential to the annulus to impart a swirling motion to the drilling fluid in the annulus, and create a vortex which attempts to pull the cuttings radially outward from the cutter formation interface and upward through the annulus.
U.S. Pat. No. 4,687,066 to Evans is directed to the use of bit nozzles having openings convergently skewed relative to the bit center line and to each other, causing ejected drilling fluid to spin downwardly in a vortex and sweep formation cuttings from the cutting face up through the annulus.
Johnson in U.S. Pat. Nos. 3,528,704 and 3,713,699, teaches the use of cavitating nozzles as cutting tools against the rock. A fluid stream is pulsated at a high frequency with enough energy to physically vaporize the fluid in a low pressure phase of the vibratory wave. The vapor bubbles produced implode in the high pressure phase of the same waves and, very close to the rock surface, cause particles of the rock to erode away in tension. Later variations are described in U.S. Pat. Nos. 4,262,757 and 4,391,339 also to Johnson, and in 4,378,853 to Chia.
U.S. Pat. No. 4,533,005 to Morris relates to a nozzle for use on a rotary drill bit in which the orientation of the jet can be adjusted after the nozzle has been installed. The jet opening is arranged and configured such that the orientation of the fluid jet emitted therefrom is changed in response to rotation of the nozzle body about its longitudinal axis.
U.S. Pat. No. 4,519,423 to Ho et al is an apparatus for mixing fluids that includes a fluid conductive means terminating in at least one non-circular orifice for emitting a jet of first fluid along a path in a pre-selected direction and a means for providing a second fluid at a location downstream of the orifice for mixing with the first fluid. In a preferred embodiment, the orifice is elliptical to generate a jet of non-circular cross-section and relatively low aspect ratio. Thus, Ho primarily deals with various jet orifices for emitting a first fluid to enhance mixing with a second fluid downstream from the orifice.
U.S. Pat. No. 4,957,242 to Schadow et al is also directed to a fluid mixing device in which a jet of first fluid is passed through a nozzle having a conical inlet section in a non-circular, elongated, exit section. The jet of first fluid mixes with the second fluid located downstream of the device. The interaction of the conical and elongated sections produces axial rotation in the first fluid causing it to mix with the second fluid.
It has also been proven that nozzles with non-axisymmetric interior bores can increase the amount of fluid entrained, improving the rate of penetration. For example, Dove et al in U.S. Pat. Nos. 5,494,124 and 5,632,349 teaches the use of a drill bit having a uniquely constructed interior bore surface for maximizing the rate of penetration of the drill bit, eliminating hydrostatic hold down forces and effectively sweeping the cuttings and formation fragments into the annulus.
It is apparent from the above that a need exists in the art to improve entrainment of the drilling fluid surrounding the nozzle in order to efficiently remove formation cuttings and other debris thus, improving the rate of drill bit penetration. Additionally, there is always a need to increase bottom hole cleaning by entrainment of the drilling fluid into a desired path. The prior art fails to meet these needs in a cost effective, novel, approach.